Downhole fracturing system and technique

ABSTRACT

A system that is usable with a well includes a first tubing string and a plurality of tubing segments. The first tubing string is deployed in the well and includes a plurality of valve assemblies, which span a segment of the first tubing string. The tubing segments are adapted to be deployed in the well inside the first tubing string and attach together in the segment of the first tubing string in a sequence to form a second tubing string in a manner that allows sequential operation of the valve assemblies of the first tubing string.

BACKGROUND

For purposes of preparing a well for the production of oil or gas, atleast one perforating gun may be deployed into the well via a conveyancemechanism, such as a wireline or a coiled tubing string. The shapedcharges of the perforating gun(s) are fired when the gun(s) areappropriately positioned to perforate a casing of the well and formperforating tunnels into the surrounding formation. Additionaloperations may be performed in the well to increase the well'spermeability, such as well stimulation operations and operations thatinvolve hydraulic fracturing.

When hydrocarbon resources include multiple reservoir intervals, whichare either discretely disposed or contained in relatively longproduction intervals, accessing the reserves may involve fracturing thewell at various depths. Thus, the above-described perforating andstimulation operations may be performed in multiple stages of the well.

SUMMARY

The summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

In an example implementation, a technique includes deploying a firsttubing string comprising a plurality of valve assemblies in a well;deploying tubing segments inside the first tubing string; and stackingthe deployed tubing segments together downhole in the well to constructa second tubing string inside the first tubing string. The stacking isused to sequence operations of the valve assemblies

In another example implementation, a system that is usable with a wellincludes a first tubing string and a plurality of tubing segments. Thefirst tubing string is deployed in the well and includes a plurality ofvalve assemblies, which span a segment of the first tubing string. Thetubing segments are adapted to be deployed in the well inside the firsttubing string and attach together in the segment of the first tubingstring in a sequence to form a second tubing string in a manner thatallows sequential operation of the valve assemblies of the first tubingstring.

In yet another example implementation, an apparatus that is usable witha well includes a tubular housing, at least one connector, a check valveand at least one wiper cup. The tubular housing is adapted to deployedthrough a lubricator inside a first tubing string and descend untetheredto a downhole location of the well to form a segment of a second tubingstring. The connector(s) attach the tubular housing to another segmentof the second tubing string downhole in the well. The check valverestricts fluid communication within a central flow path of the tubularhousing. The wiper cup(s) form an annular seal between the tubularhousing and the first tubing string.

Advantages and other features will become apparent from the followingdrawings, description and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of a well having a liner string withfracturing valve assemblies according to an example implementation.

FIGS. 2A, 2B and 2C are schematic diagrams of the well of FIG. 1illustrating a sequence of multiple stage fracturing operationsaccording to an example implementation.

FIG. 3 is a flow diagram depicting a technique to deploy tubing segmentsin an outer tubing string to sequentially open valve assemblies of theouter tubing string according to an example implementation.

FIGS. 4A and 4B collectively depict a flow diagram of a technique toperform multiple stage fracturing operations according to an exampleimplementation.

FIG. 5 is a partial cross-sectional view of a bottom hydraulicfracturing valve assembly of the liner string of FIG. 1 according to anexample implementation.

FIGS. 6, 7, 8 and 9 are perspective views of bottomhole assemblies of afracturing system according to an example implementation.

FIG. 10 is a partial cross-sectional view of a tubing anchor latch of abottomhole assembly according to an example implementation.

FIG. 11 is a partial cross-sectional view of an upper tubing connectorof a bottomhole assembly according to an example implementation.

FIG. 12 is a partial cross-sectional view of a lower tubing connector ofa bottomhole assembly according to an example implementation.

FIG. 13 is a partial cross-sectional view of a check valve assemblyaccording to an example implementation.

FIG. 14 is a partial cross-sectional view of a blast joint according toan example implementation.

FIG. 15 is a partial cross-sectional view of a fracturing valve assemblyaccording to an example implementation.

FIG. 16 is a partial cross-sectional view of a tubing cup tool accordingto an example implementation.

FIG. 17 is a partial cross-sectional view of a shiftable ported valveassembly according to an example implementation.

FIG. 18 is a partial cross-sectional view illustrating landing of thetubing cup tool of FIG. 16 inside the fracturing valve assembly of FIG.15 for a closed state of the fracturing valve assembly according to anexample implementation.

FIG. 19 is a partial cross-sectional view illustrating landing of thetubing cup tool of FIG. 16 in the fracturing valve assembly of FIG. 5for an open state of the fracturing valve assembly according to anexample implementation.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to providean understanding of features of various embodiments. However, it will beunderstood by those skilled in the art that the subject matter that isset forth in the claims may be practiced without these details and thatnumerous variations or modifications from the described embodiments arepossible.

As used herein, terms, such as “up” and “down”; “upper” and “lower”;“upwardly” and downwardly”; “upstream” and “downstream”; “above” and“below”; and other like terms indicating relative positions above orbelow a given point or element are used in this description to moreclearly describe some embodiments. However, when applied to equipmentand methods for use in environments that are deviated or horizontal,such terms may refer to a left to right, right to left, or otherrelationship as appropriate.

Systems and techniques are disclosed herein for purposes of performingfracturing operations in multiple zones, or stages, of a well, withoutthe use of conventional deployment mechanisms, such as a wireline or acoiled tubing, to intervene in the well to operate fracturing valves.Moreover, the systems and techniques that are disclosed herein may beused in cased hole completions as well as in open hole completions.

As a more specific example, FIG. 1 depicts an example well 100, whichincludes a lateral wellbore 110 that extends through one or more zones,or stages, of the well 100. For the example of FIG. 1, the lateralwellbore 110 extends from a main wellbore 102, which may be cased by acasing string 104, as depicted in FIG. 1. Moreover, for the example ofFIG. 1, the lateral wellbore 110 is an open hole completion in which aliner string 120 extends through the stage(s) through which the wellbore110 extends.

For this example, the liner string 120 has an upper packer 122 as wellas one or more additional packers 123, which are radially expanded, orset, for purposes of forming isolated stages associated with a wellbore110. The packer 122, 123 may be a mechanically-set packer, a weight-setpacker, a hydraulically-set packer, a swellable material-based packer, abladder-based packer, and so forth, as can be appreciated by the skilledartisan.

In accordance with example implementations, the liner string 120contains a bottom hydraulic fracturing sub, or valve assembly 130, aswell as additional fracturing subs, or valve assemblies 140 (Nfracturing valve assemblies 140-1. . . 140-N, being depicted as examplesin FIG. 1) that are disposed above the assembly 130. In this manner, asfurther described herein, the fracturing valve assemblies 130 and 140are run into the well as part of the liner string 120 in respectiveclosed states (i.e., in states to block fluid communications between thecentral passageway of the liner string 120 and the regions outside ofthe valve assemblies 130 and 140). After the liner string 120 isinstalled and the fracturing is to begin, the fracturing valveassemblies 130 and 140 are sequentially opened beginning with a toe end160 of the wellbore 110 and ending near the heel end 122 of the wellbore110. As each fracturing valve assembly 130, 140 is opened, one or moresurface pumps 110 at an earth surface E of the well 100 may pump fluid112 into the well, which is routed to the central passageway of theliner string 120 and into the stage associated with the opened valve130, 140 for purposes of forming a respective fracturing network.

It is noted that in further implementations, the liner string 120 may bereplaced with a casing string (i.e., a string that lines and supportsthe wellbore 110), which is cemented in the wellbore 110 and containscasing-conveyed fracturing valve assemblies in place of the valveassemblies 130 and 140. Thus, many variations are contemplated, whichare within the scope of the appended claims.

It is noted that the well 100 may be a terrestrial well or a subseawell, depending on the particular implementation. Moreover, although alateral wellbore 110 is specifically disclosed herein to illustratefracturing systems and techniques, it is understood that in accordancewith further implementations, the techniques and systems that aredisclosed herein may likewise be applied to vertically-extending or, ingeneral, non-lateral wellbores.

Instead of using a conventional deployment mechanism, such as a coiledtubing string or wireline, in an intervention to operate the fracturingvalve assemblies, as disclosed herein, the fracturing valve assemblies140 are sequentially opened by deploying tubing segments into thecentral passageway of the liner string 120. In this manner, the deployedtubing segments each have a sufficiently small length (a length of 25feet or less, as an example) to allow the segment to pass through Earthsurface-disposed lubricator 108 of the well 100. The deployed tubingsegments may be guided into the liner string 120 via a whipstock 106 inthe main wellbore. In further example implementations, the well may be amulti-stage stimulation well that does not include a whipstock. Thetubing segments are further constructed so that the first deployedtubing segment anchors to the bottom hydraulic fracturing valve assembly130 and the remaining deployed tubing segments attach end-to-end forpurposes of forming an inner string within the liner string 120.

As the tubing segments are stacked together and assembled downholeinside the liner string 120, the tubing segments form central passagewayand annular seals within the liner string 120 that permit the sequentialoperation of the fracturing valve assemblies 140, as further disclosedherein. At the conclusion of the multiple stage fracturing operationsthat the inner tubing string may be subsequently used as a productiontubing string to receive produced well fluid from the fractured stages.

As a more specific example, the above-described multiple stagefracturing operations may begin by first opening the bottom hydraulicfracturing valve assembly 130 and using the assembly 130 to form abottom fracture zone 200 that is illustrated in FIG. 2A. Morespecifically, in accordance with example implementations, the bottomhydraulic fracturing valve assembly 130 is constructed to respond topressure inside the central passageway of the liner string 120 thatexceeds a predetermined threshold.

Initially, the fracturing valve assemblies 140 are all closed.Therefore, by pumping fluid into the central passageway of the linerstring 120, hydraulic pressure inside the central passageway may beincreased to cause the valve assembly 130 to open its radial ports andestablish fluid communication between the central passageway of theliner string 120 and the region that is outside of the valve assembly130. As a more specific example, in accordance with exampleimplementations, the valve assembly 130 may be a tubingpressure-operated sleeve valve assembly. At the conclusion of thecommunication of fracturing fluid (a mixture of proppant and a carrierfluid, for example) to create the fractured zone 200, operations thenproceed to operate the next, adjacent fracturing valve assembly 140-1.

More specifically, referring to FIG. 2B, a first tubing segment 210-1 isdeployed through the lubricator 108 and pumped into the liner string 120until the tubing segment 210-1 lands in and is attached, or anchored, tothe bottom hydraulic fracturing valve assembly 130. As explained furtherherein, the tubing segment 210-1 is the first of many tubing segments210 that may be deployed into the liner string 120. As described furtherherein in connection with FIGS. 11 and 12, each tubing segment 210 isconstructed to form a latched connection with the tubing segment 210below (except for the tubing segment 210-1, which anchors to theassembly 10) and the tubing segment 210 above (except for the uppermostsegment 210). Thus, the tubing segments 210 are collectively stackedtogether inside the liner string 120 to form an inner string. As thetubing segments 210 are stacked together, the tubing segments 210 formannular seals and passageway restrictions at the appropriate intervalsso that a fluid pressure may be applied against these seals andrestrictions to open the fracturing valve assemblies 140. Thus, theprocess of stacking of the tubing segments 210 inside the liner string120 may be interrupted at various points to for purposes of pressuringfluid to opening the fracturing valve assemblies 140.

For example, the stacking of the tubing segments 210 ceases near thefracturing valve assembly 140-1. As discussed further herein andillustrated in FIGS. 18 and 19, due to a fluid restriction (check valve,for example, as described herein) inside the tubing segments 210 and anannular seal outside of the tubing segments (a cup seal, for example, asdescribed herein), fluid may be pumped into the well to pressurize apiston surface of the fracturing valve assembly 140-1 for purposes ofopening the radial ports of the assembly 140-1. Fluid may continue to bepumped, which flows through the radial ports of the assembly 140-1 toform a second fracture zone 220.

Each tubing segment 210 may be formed from one or multiple bottomholeassemblies (BHAs), which are described herein.

In general, the above-described process may be repeated by deployingadditional tubing segments 210 into the liner string 120, stacking thetubing segments 210 end-to-end together and forming corresponding sealsthat allow the corresponding sequential operation of other valveassemblies 140.

Referring to FIG. 2C, thus, at the conclusion of the fracturingoperations, a tubing segment 210-N configures the uppermost fracturingvalve assembly 140-N to be open to form a corresponding fracture zone230. At this point, the deployed and now connected tubing segments 210form an inner string (a production tubing string, for example) insidethe liner string 120.

Thus, referring to FIG. 3, in accordance with example implementations, atechnique 300 includes deploying (block 302) a first tubing stringcontaining valve assemblies into a well and deploying (block 304) tubingsegments inside the first tubing string. Pursuant to the technique 300,the deployed segments are stacked together (block 306) downhole in thewell to construct a second tubing string. The stacking process may beused, pursuant to block 308, to sequence the opening of the valveassemblies.

As a more specific example, FIG. 5 depicts the bottom hydraulicfracturing valve assembly 130, in accordance with an exampleimplementation. It is noted that FIG. 5, as well as additional figuresof the present application, depict partial cross-sectional views. Inthis regard, FIG. 5, for example, depicts an upper cross section of thevalve assembly 130 relative to a longitudinal axis 500 of the linerstring 120, with it being understood that the lower cross section of theassembly 130 may be derived by mirroring the upper cross section aboutthe longitudinal axis 500.

In general, the bottom hydraulic fracturing valve assembly 130 includesa tubular housing 504 that is concentric with the longitudinal axis 500.The housing 504 contains radial ports 510 and an inner sleeve 530 thatis concentric with the longitudinal axis 500 and controls fluidcommunication through the radial ports 510.

More specifically, FIG. 5 depicts the valve assembly 130 in itsrun-in-hole state. In this state, the inner sleeve 530 blocks fluidcommunication between the central passageway of the valve assembly 130and the radial ports 510. As depicted in FIG. 5, seal elements 511 and513 form seals between the inner surface of the housing 504 and theouter surface of the sleeve 530. Moreover, the sleeve 530 is retained inits initial position to close fluid communication through the ports 510via one or more shear pins 531.

Fluid inside the central passageway of the liner string 120 causes theinner sleeve 530 to shift, or translate, along the longitudinal axis 500to open the valve assembly 130 to therefore allow fluid flow through theradial ports 510. A ratchet sleeve 532 engages ratchet teeth 533 formedon the outer surface of the sleeve 530, in accordance with exampleimplementations, to secure the valve assembly 130 in the open state.

Among its other features, in accordance with example implementations,the valve assembly 130 includes pin threads 520 at its lower end to forma corresponding tubing connection and box threads 544 at its upper endto form a corresponding connection to the upper portion of the linerstring 120. The valve assembly 130 further includes an interior anchorlatch profile 542 that is formed in the interior surface of the housing504 for purposes of engaging a latch of a bottom hole assembly (i.e., atubing segment) as further disclosed herein. Moreover, in accordancewith example implementations, the inner surface of the housing 504further includes a seal bore 540 for purposes of engaging seals of thebottom hole assembly.

As a more specific example, each tubing segments 210 that is deployed inthe liner string 120 may contain one or more of the following bottomhole assemblies (BHAs). In this manner, referring to FIG. 6, inaccordance with example implementations, a first BHA 600 may be deployedin the liner string 120 after the fracture zone 200 is formed. The firstBHA 600 includes a tubing anchor latch 604 near its lower end forpurposes of engaging the anchor latch profile 542 (see FIG. 5) of thebottom hydraulic fracturing valve assembly 130 and anchoring the firstBHA 600 to the valve assembly 130.

The first BHA 600 further includes a lower seal bore connector 602 forpurposes of extending into the bottom hydraulic fracturing valveassembly 130 and forming a seal with the seal bore 540 of the assembly130. In general, the BHA 600 may be formed from a tubular housing 608that is concentric with a longitudinal axis 601 of the BHA 600. At itsupper end, the first BHA 600 includes an upper tubing connector 612 thatconnects to the next deployed tubing segment.

For purposes of aiding pumping of the first BHA 600 into the linerstring 120, in accordance with example implementations, the first BHA600 includes a pump down ring 610 near its upper end. Moreover, upholefrom the pump down ring 610, the first BHA 600 may include a seal bore614 to form a corresponding fluid seal with the adjacent uphole tubingsegment as well as a ratchet profile 620 to secure the connection withthis tubing segment, as further disclosed herein.

Thus, the first BHA 600 may be, in accordance with exampleimplementations, the first tubing segment that is deployed through thelubricator 108 (FIG. 1) and into the liner string 120.

In accordance with example implementations, the next tubing segment thatis deployed into the liner string may be a second BHA 700 that isdepicted in accordance with FIG. 7. In this manner, referring to FIG. 7,the second BHA 700 is formed from a tubular housing 706 that isgenerally concentric with the longitudinal axis 601. The second BHA 700includes a lower tubing connector 702 that is constructed to form acorresponding sealed and mated connection with the upper tubingconnector 612 of the first BHA 600. The second BHA 700 further includesan upper tubing connector 612 that is constructed to form a sealed andmechanical connection to the next tubing segment.

In general, the function of the second BHA 700 is to serve as a spacerbetween the first BHA 600 and a third BHA 800 (described below inconnection with FIG. 8) that forms the seals with the first valveassembly 140-1 for purposes of operating this assembly 140-1. Ingeneral, the length of a given BHA, such as the first BHA 600 or thesecond BHA 700, may be limited by the lubricator 108 (see FIG. 1, forexample). Therefore, one or multiple second BHAs 700 may be deployedinto the liner string 120 for purposes of establishing the appropriatespacing between the first BHA 600 that anchors the inner string to theliner string 120 and the third BHA 800.

Referring to FIG. 8, the third BHA 800 forms the flow restriction andannular seal for purposes of operating the lowermost fracturing valveassembly 140-1 (see FIG. 1, for example). In this regard, the third BHA800, in accordance with example implementations, is formed from atubular housing 810 that is generally concentric with the longitudinalaxis 601. The third BHA 800 includes a lower tubing connector 702 thatis constructed to form a sealed and mechanical connection with the uppertubing connector 612 of either the first BHA 600 or second BHA 700,depending on the particular implementation.

The third BHA 800 further includes an upper ratchet profile 826 and sealnose 828 for purposes of forming a corresponding mechanical and sealedconnection with a fourth BHA 900 (as described below in connection withFIG. 9) that is deployed in the liner string 120 above the third BHA800, as further disclosed below. The third BHA 800 includes a checkvalve assembly 804 that establishes a directional flow through the BHA800. More specifically, in accordance with example implementations, thecheck valve assembly 804 permits an uphole flow but prevents a downholeflow. Thus, the check valve assembly 804 allows for a fluid column to beestablished uphole of the assembly 804 for purposes of permitting thefluid column to be pressurized to actuate the lowermost valve assembly140-1. The check valve assembly 804 further permits a flow of theproduction fluid from the well at the conclusion of the multiple stagefracturing operations.

Among its other features, the third BHA 800 includes a cup tool 820,which forms an annular seal between the exterior of the tubular housing810 and the interior of the liner string 120. More specifically, asfurther described herein, the annular seal is formed at the appropriateposition inside or slightly below the lowermost fracturing valveassembly 140-1 to allow pressure to actuate the assembly's sleeve valveto shift the assembly 140-1 open.

In accordance with example implementations, the third BHA 800 includes ablast joint 824 that is disposed uphole of the cup tool 820. In general,the blast joint 824 is positioned to span the region inside the radialports of the lowermost fracturing valve assembly 140-1. As its nameapplies, the blast joint 824 provides a degree of erosion protection forthe third BHA 800.

Referring to FIG. 9, the fourth BHA 900 is landed in proximity to thefracturing valve assemblies 140-2. . . 140-N for purposes of openingthese valve assemblies. In this regard, between any two of the valveassemblies 140-2 to 140-N, one or more second BHAs 700 may first bedeployed with the last BHA being the fourth BHA 900. The fourth BHA 900,in general, has a design that is similar to the third BHA 800, exceptthat the fourth BHA 900 includes a shiftable ported sub, or shiftablevalve assembly 910, which may be used for purposes of controlling theflow of production fluid from a particular stage of the well.

In this regard, the fourth BHA 900 is deployed downhole with itsshiftable ported valve assembly 910 closed, and the assembly 910 remainsclosed during the fracturing operations. Subsequently, a shifting tool,for example, may be deployed inside the inner tubing string to open thevarious assemblies 910, as well as selectively close certain assemblies910 for purposes of isolating regions of the well in which production isnot desired, such as, for example, regions of the well in which anexcessive amount of water is being produced. In addition to theshiftable ported valve assembly 910, the fourth BHA 900 has a tubularhousing 904 that is concentric with the longitudinal axis 601; and theBHA 900 contains a check valve 804, a cup tool 820, a blast joint 824, aratchet profile 826 and a seal 828, similar to the third BHA 800.Moreover, the fourth BHA 900 includes a lower tubing connector 702.

Thus, in accordance with example implementations, the following BHAs areused for the various stages. At least two BHAs are used in the first(bottommost) stage; and at least one BHA is used in the subsequentstages, depending on the valve assembly-to-valve assembly spacing. Morespecifically, the first stage between the lowermost hydraulic fracturingvalve assembly 130 and the fracturing valve assembly 140-1 includes twoor more BHAs, depending on the spacing between the valve assemblies 130and 140-1: the first BHA 600 at the bottom of the stage; the third BHA800 at the top of the stage; and zero, one or more than one second BHA700 between the first BHA 600 and the third BHA 800. Each of the otherstages (i.e., the stages between fracturing valve assemblies 140)includes one or more BHAs, depending on the spacing between adjacentvalve assemblies 140: zero, one or more than one second BHA 700 at thebottom of the stage; and one fourth BHA 900 at the top of the stage.

To summarize, a technique 400 that is depicted in FIGS. 4A and 4B may beused in accordance with example implementations. Referring to FIG. 4A,pursuant to the technique 400, a bottom hydraulic fracturing valveassembly of a liner string is opened (block 402) and the correspondingstage is fractured by communicating fracturing fluid via the openedbottom fracturing valve assembly, pursuant to block 404. Next, the firstBHA of the inner string is deployed into the liner string, pursuant toblock 406. Next, one or more second BHAs are deployed, pursuant to block408. Subsequently, a third BHA is deployed, pursuant to block 410. Thefirst fracturing valve assembly uphole of the bottom hydraulicfracturing valve assembly may then be opened, pursuant to block 412, sothat the second stage may be fractured by communicating fluid throughthe first fracturing valve assembly, pursuant to block 414.

Referring to FIG. 4B, next, one or more second BHAs may be deployed intothe liner string, pursuant to block 416 and then the fourth BHA isdeployed into the liner string, pursuant to block 418. The nextfracturing valve assembly of the liner string may then be opened (block420) so that the corresponding stage may be fractured (block 422).Blocks 416, 418, 420 and 422 may then be repeated of the additionalvalve assemblies. In this regard, if a determination (decision block422) is made that another stage is to be fractured, control returns toblock 416.

Referring to FIG. 10, in accordance with example implementations, thetubing anchor latch 604 has a tubular housing 1000 that is concentricabout the longitudinal axis 601. The latch 604 includes a seal stack1002 that is disposed on the outside of the tubular housing 1000 forpurposes of forming a seal between the tubing anchor latch 604 and theseal bore 540 of the bottom hydraulic fracturing valve assembly 130 (seeFIG. 5). The tubing anchor latch 604 further includes an anchor snaplatch 1004 that is constructed to engage the anchor latch profile 542(see FIG. 5) of the bottom fracturing valve assembly 130. Moreover, inaccordance with example implementations, the tubing anchor latch 604includes a tubing box thread 1014 for purposes of securing the tubinganchor latch 604 to the remainder of the first BHA 600.

Referring to FIG. 11, in accordance with example implementations, theupper tubing connector 612, such as, for example, the upper tubingconnector 612 of the first and second BHAs 600 and 700, includes atubular housing 1100 and one or multiple radially-extending centralizers1104 that extend therefrom. The upper tubing connector 612 furtherincludes a pump down ring 610 (an elastomer ring, for example), whichcircumscribes the tubular housing 1100 and may be secured in place by apump down ring retaining nut 1110. As further depicted in FIG. 11, amongits other features, the upper tubing connector 612 may include a ratchetprofile 620 for purposes of engaging an adjacent BHA disposed above theconnector 612 as well as a seal nose 614 for purposes of providing asmooth surface for forming a corresponding fluid seal with the BHA.Moreover, the upper tubing connector 612 includes a box thread 1101 forpurposes of forming a corresponding mechanical and sealed connectionwith the downhole components of the associated BHA.

Referring to FIG. 12, in accordance with example implementations, thelower tubing connector 702 of the second 700, third 800 and fourth 900BHAs includes a generally tubular housing 1202 that includes a boxthread 1230 for purposes of forming mechanical and fluid sealconnections with the remainder of the associated BHA. Moreover, a sealstack 1224 is disposed inside the tubular housing 1202 for purposes offorming a sealed connection with the corresponding seal nose of theinserted BHA. As depicted in FIG. 12, the lower tubing connector 702includes a ratchet ring 1220 for purposes of forming a ratchetconnection with the corresponding ratchet profile of the inserted BHA.The ratchet ring 1220 may be held in place by a corresponding ratchetring 1208. Moreover, among its other features, the lower tubingconnector 702 may include radially extending centralizers 1204, inaccordance with example implementations.

Referring to FIG. 13, in accordance with example implementations, thecheck valve assembly 804 may be formed from a generally tubular housing1320 that is concentric about the longitudinal axis 601. In general, thecheck valve assembly 804 includes an inner box thread 310 at its upperend and an inner box thread 1304 at its lower end for purposes ofcoupling the check valve assembly 804 in line with the remainingcomponents of the BHA. The check valve assembly 804 includes an interiorvalve seat 1324 that is formed on the interior surface of the housing1320 for purposes of receiving a ball 1308 to prevent fluid flow in thedownhole direction. In this regard, when the ball 1308 is seated in theseat 1324 in response to pressure uphole of the ball 1308, fluid flowthrough the central passageway of the check valve assembly 804 isprevented.

The check valve assembly 804 further includes an interior sleeve 1330that has a corresponding opening 1334 to receive the ball 1308 whenpressure from downhole of the ball 1308 pushes the ball 1308 into theseat 1334. Due to the annular clearance between the seat 1330 and theinterior of the tubular housing 1320 and the radial ports 1336 of thesleeve 1330, fluid directed uphole is communicated around the ball 1308and is allowed to flow through the check valve assembly 804. Thus,produced well fluid may flow uphole through the check valve assembly804.

In accordance with example implementations, the ball 1308 may beconstructed from one or more dissolvable materials. In this regard, theball 1308 may degrade or oxidize over time such that eventually one ormore parts of the ball 1308 disintegrate to the extent that allows theball 1308 to pass out of the check valve assembly 804. This may bebeneficial after completion of the fracturing operations open up theinterior of the inner string for interventions.

As a more specific example, in accordance with example implementations,the ball 1308 may be formed from a degradable/oxidizable material, whichretains its structural integrity for the fracturing operations. However,over a longer time (a week or a month, as examples), thedegradable/oxidizable material(s) of ball 1038 may sufficiently degradein the presence of wellbore fluids to cause a partial or total collapseof the fluid barrier presented by the ball 1308. In accordance withexample implementations, dissolvable or degradable alloys may be usedsimilar to one or more of the alloys that are disclosed in the followingpatents: U.S. Pat. No. 7,775,279, entitled, “Debris-Free PerforatingApparatus and Technique,” which issued on Aug. 17, 2010; and U.S. Pat.No. 8,211,247, entitled, “Degradable Compositions, ApparatusCompositions Comprising Same, And Method of Use,” which issued on Jul.3, 2012.

Referring to FIG. 14, in accordance with example implementations, theblast joint 824 may include a tubular housing 1410 that is generallyconcentric with the longitudinal axis 601. The tubular housing 1410includes an increased diameter section 1411 to provide a thicker, fluidcorrosion-resistant, section of the blast joint 824 that coincides withthe position of the ports of the fracturing valve assembly 140. Asdepicted in FIG. 14, at its upper end, the blast joint 824 may include aratchet profile 826 and seal nose 828 for engaging the lower tubingconnector of the adjacent BHA, and the blast joint 824 may include a pinthread 1404 for purposes of forming a mechanical and fluid seal with thedownhole part of its associated BHA.

FIG. 15 depicts the fracturing valve assembly 140, in accordance withexample implementations. In general, the fracturing valve assembly 140is formed from a tubular housing 1520 that is generally concentric withthe longitudinal axis 500 of the liner 120. The tubular housing 1520includes radial ports 1540, and an inner sleeve 1518 is disposed insidethe tubular housing 1520 for purposes of controlling the communicationof the fluid through the radial ports 1540. In this regard, seals 1504and 1505 may be disposed at the lower and upper ends, respectively, ofthe inner sleeve 1518 for purposes of blocking flow through the radialports 1540 in the closed state of the fracturing valve assembly 140.

In accordance with example implementations, the fracturing valveassembly 140 includes a ratchet sleeve 1552 that engages a correspondingshifting profile 1554 on the outer surface of the inner sleeve 1518 forpurposes of retaining the fracturing valve assembly 140 in the openstate after the assembly 140 is opened. Moreover, as depicted in FIG.15, in accordance with example implementations, a shifting profile 1550may be formed in the interior surface of the inner sleeve 1518 forpurposes of allowing the sleeve 1518 to be engaged by a shifting tool toselectively manipulate the open or closed state of the valve assembly140 via the use of the tool.

Referring to FIG. 16, in accordance with example implementations, thetubing cup tool 820 includes a generally tubular housing 1608 that isconcentric with the longitudinal axis 601. The tubing cup tool 820includes box threads 1604 and 1606 at its lower and upper ends,respectively, for purposes of coupling the tubing cup tool 820 in linewith the remaining components of the BHA. In general, the tubing cuptool 820 includes high pressure high temperature (HPHT) wiper cups 1610and 1614 that circumscribe the tubular housing 608 and are constructedto form respective annular seals between the BHA and the interiorsurface of the liner string 120.

Referring to FIG. 17, in accordance with example implementations, theshiftable ported valve assembly 910 includes lower 1702 and upper 1704box threads for purposes of coupling the assembly 910 in line with theremaining components of the BHA. In general, the shiftable ported valveassembly 910 includes a generally tubular housing 1705, which includesradial ports 1740 for communicating fluid between the central passagewayof the assembly 910 and the region outside of the housing 1705.

The shiftable ported valve assembly 910 further includes an inner sleeve1720 that has a corresponding inner profile 1721, which is constructedto be engaged by a shifting tool for purposes of transitioning the valveassembly 910 between its open and closed states. The state of theshiftable ported valve assembly 910 depicted in FIG. 17 is the openstate in which bonded seals 1730 and 1731 disposed on the outside of theinner sleeve 1720 are translated away from the radial ports 1740 toallow fluid communication through the ports 1740. However, the innersleeve 1720 may be translated uphole to dispose the seals 1730 and 1731on either side of the ports 1740 to block fluid communication and thus,transition the valve assembly 910 into its closed state.

As depicted in FIG. 17, in accordance with example implementations, theinner sleeve 1720 may be connected to a collet 1709 that engages acorresponding collet profile 1710 that is formed in the interior surfaceof the outer housing 1705 when the valve assembly 910 is in its closedstate for purposes of securing, or retaining, the valve assembly 910 inthis closed state. An upward shifting force via a shifting tool engagingthe shifting profile 1721, however, may be used to disengage the collet1709 from the profile 1710 to allow the valve assembly 910 to be closed.

FIG. 18 is an illustration 1800 depicting the landing of the tubing cuptool 820 inside the fracturing valve assembly 140. For this example, thevalve assembly 140 is in its closed state. As shown, the cup tool 820forms an annular seal that allows hydraulic pressure to be exerted onthe inner sleeve 1518. Therefore, upon exertion of sufficient fluidpressure, the inner sleeve 720 may be shifted downhole, as depicted inan illustration 1900 of FIG. 19. Referring to FIG. 19, thus, theshifting of the sleeve 1518 opens fluid communication through the radialports 1540.

While a limited number of examples have been disclosed herein, thoseskilled in the art, having the benefit of this disclosure, willappreciate numerous modifications and variations therefrom. It isintended that the appended claims cover all such modifications andvariations.

What is claimed is:
 1. A method comprising: deploying a first tubingstring comprising a plurality of valve assemblies in a well; deployingtubing segments inside the first tubing string; stacking the deployedtubing segments together downhole in the well to construct a secondtubing string inside the first tubing string; and using the stacking tosequence operations of the valve assemblies.
 2. The method of claim 1,wherein the using comprises opening the valve assemblies one at a timeand in response to opening each valve assembly communicating fluidthrough the assembly to fracture a region of the well.
 3. The method ofclaim 1, wherein the first tubing string further comprises a bottomvalve assembly disposed below the plurality of valve assemblies, themethod further comprising: before the deploying of the tubing segmentsbegins, opening the bottom valve assembly and communicating fluidthrough the bottom valve assembly to fracture a region of the well. 4.The method of claim 3, wherein deploying the tubing segments comprisesdeploying a set of at least one segment of the tubing segments to anchorthe set to the bottom valve assembly, form an annular seal between theset and the first tubing string and restrict flow through the set to asingle flow direction.
 5. The method of claim 4, further comprising:using the annular seal and the flow restriction to open one of the valveassemblies of the plurality of valve assemblies.
 6. The method of claim1, wherein deploying the tubing segments comprises deploying a set of atleast one segment of the tubing segments to restrict flow between two ofthe valve assemblies to a single direction and form an annular sealbetween the set and the first tubing string.
 7. The method of claim 6,further comprising: using the annular seal and the flow restriction toopen one of the valve assemblies of the two valve assemblies.
 8. Themethod of claim 1, further comprising: using the second tubing string asa production tubing string.
 9. The method of claim 8, wherein deployingthe tubing segments comprises deploying at least one tubing segmentcomprising a ported valve assembly to selectively isolate a region ofthe well from hydraulic communication with the production tubing string.10. The method of claim 1, wherein: the first tubing string furthercomprises a bottom valve assembly disposed below the plurality of valveassemblies, the deployed tubing segments comprise a first bottom holeassembly, second bottom hole assemblies and a third bottom holeassembly; and the deploying and stacking comprises: deploying the firstbottom hole assembly and anchoring the first bottom hole assembly to thebottom valve assembly; deploying at least one of the second bottom holeassemblies based on a spacing between the bottom valve assembly and alowermost valve assembly of the plurality of valve assemblies; deployingthe third bottom hole assembly to restrict flow between the lowermostvalve assembly of the plurality of valve assemblies and the third bottomhole assembly to a single direction and form an annular seal between thethird bottom hole assembly and the first tubing string.
 11. The methodof claim 10, wherein: using the flow restriction and the annular seal toopen the lowermost valve assembly of the plurality of valve assemblies.12. The method of claim 11, wherein: the deploying and stacking furthercomprises: deploying at least one additional second bottom hole assemblyof the second bottom hole assemblies based on a spacing between thelowermost valve assembly and the adjacent valve assembly of theplurality of valve assemblies uphole from the lowermost valve assembly;deploying a fourth bottom hole assembly to restrict flow between theadjacent valve assembly of the plurality of valve assemblies and thefourth bottom hole assembly to a single direction, form an annular sealbetween the fourth bottom hole assembly and the first tubing string, andallow selective fluid communication between a region outside the secondtubing string and an interior flow path of the second tubing string. 13.A system usable with a well, comprising: a first tubing string to bedeployed in the well and comprising a plurality of valve assembliesspanning a segment of the first tubing string; and a plurality of tubingsegments, wherein the tubing segments are adapted to: be deployed in thewell inside the first tubing string; and attach together in the segmentof the first tubing string in a sequence to form a second tubing stringin a manner that allows sequential operation of the valve assemblies ofthe first tubing string.
 14. The system of claim 13, wherein the secondtubing string comprises a production tubing string.
 15. The system ofclaim 13, wherein the plurality of valve assemblies comprises ports tocommunicate a fracturing fluid.
 16. The system of claim 13, wherein thefirst tubing string comprises a liner string or a casing string.
 17. Anapparatus usable with a well, comprising: a tubular housing adapted todeployed through a lubricator inside a first tubing string and descenduntethered to a downhole location of the well to form a segment of asecond tubing string; at least one connector to attach the tubularhousing to another segment of the second tubing string downhole in thewell; a check valve to restrict fluid communication within a centralflow path of the tubular housing; and at least one wiper cup to form anannular seal between the tubular housing and the first tubing string.18. The apparatus of claim 17, further comprising a ported valveassembly to be selectively operated to regulate fluid communicationbetween the central flow path of the tubular housing and a regionoutside of the housing.
 19. The apparatus of claim 17, furthercomprising a seal nose to form a seal between the central flow path andthe central flow path of the another segment of the second tubingstring.
 20. The apparatus of claim 17, further comprising a ratchetteeth to engage a ratchet sleeve of the another segment of the secondtubing string.